ML17326B365
| ML17326B365 | |
| Person / Time | |
|---|---|
| Site: | Cook  |
| Issue date: | 03/31/1988 |
| From: | Alexich M INDIANA MICHIGAN POWER CO. (FORMERLY INDIANA & MICHIG |
| To: | Davis A NRC OFFICE OF ADMINISTRATION & RESOURCES MANAGEMENT (ARM) |
| References | |
| AEP:NRC:1056, IEB-88-002, IEB-88-2, NUDOCS 8804110191 | |
| Download: ML17326B365 (24) | |
Text
REGUL..>ORY INFQRMATIQN DISTRIBUT1 SYSTEM (RIDS)
ACCESSION NOR: 88041 10191 DQC. DATE: 88/03/31 NOTARIZED:
YES DOCKET ¹ FACIL: 50-315 Donald C.
Cook Nuclear Power Plant.
Unit 1>
~4 05000315 50-31 6 Donald C.
Cook Nuc lear PoUJer P) ant>
Unit 2>
Indiana ic 0500031 6 AUTH. NAME AUTHOR AFFILIATION ALEXICH> M. P.
(Formerly Indiana h Michigan Ele RECIP. NAME RECIPIENT AFFILIATION DAVIS> A. B.
Document Control Branch (Document Control Desk>
SUBJECT:
Responds to NRC Bulletin 88-02>
"Rapidly Propagating Fatigue Cracks in Steam Generator Tubes."
DISTRIBUTION CODE:
IE13D COPIES RECEIVED: LTR ENCL SIZE:
TITLE: Bulletin Response>
88-02 Rapidly Propagating Fatigue Cracks in Steam NOTES:
REC IP IENT ID CODE/NAME PD3-3 LA STANG> J INTERNAL:
AEOD. DSP AEOD/DSP/TPAB NRR NEIGHBORS> D NRR/DEST/ADS 7E NRR/DOEA/EAB fi NRR/DREP/EPBiOA 02
~ILE 01 COP IES LTTR ENCL 0
1 1
1 1
1 1
1 1
f 1
f 1
1 1
1 1
f REC IP IENT ID CODE/NAME PD3-3 PD AEOD/DOA NRR MURPHY> E NRR/DEST/ADESH3.
NRR/DEST/MEB 9H NRR/DOE*/GCB ii NRR /P M*S/ILRB12 RES/DE/EIB CQP IES LTTR ENCL 1
1 I
1 1
1 1
1 1
f 1
1 1
1 EXTERNAL:
LPDR NSIC 1
1 1
1 NRC PDR 1
1 TOTAL NUMBER OF COPIES REQUIRED:
LTTR 21 ENCL 20
indiana Micbiga Power Company P.O. Box 16631 Columbus, OH 43216 Z
INCIAi"8'CNICAL PQvVrn2 AEP:NRC;1056 Donald C.
Cook Nuclear Plant Units 1 and 2
Docket Nos.
50-315 and 50-316 License Nos.
RESPONSE
TO NRC BULLETIN 88-02, RAPIDLY PROPAGATING FATIGUE CRACKS IN STEAM GENERATOR TUBES U.S. Nuclear Regulatory Commission Attn:
Document Control Desk Washington, D.C.
20555 Attn:
A. B. Davis March 31, 1988
Dear Mr. Davis:
This letter responds to NRC Bulletin No. 88-02, "Rapidly Propagating Fatigue Cracks in Steam Generator Tubes."
NRC Bulletin 88-02 requests information regarding steam generator tube inspections and programs to minimize the probability of a rapidly propagating fatigue failure.
Attachment 1 to this letter contains our response to the NRC Bulletin 88-02 action items.
Included are our evaluation of steam generator tube denting, a description of in-place leak detection
- methods, and a proposed long term corrective action program.
Sincerely, M.
. Ale ch Vice President cm Attachment cc:
D.
H. Williams, Jr.
W.
G. Smith, Jr.
- Bridgman R.
C. Callen G. Bruchmann G. Charnoff NRC Resident Inspector
- Bridgman 8804ii019i 88033i PDR ADOCK 05000318 9
Mr. A. B. Davis AEP:NRC:1056 STATE OF OHIO COUNTY OF FRANKLIN Milton P. Alexich, being duly sworn, deposes and says that he is the Vice President of licensee Indiana Michigan Power Company, that he, has read the foregoing response to NRC Bulletin 88-02, "Rapidly Propagating Fatigue Cracks in Steam Generator Tubes,"
and knows the contents thereof; and that said contents are true to the best of his knowledge and belief.
P. Ale ich Vice Pre ident ubscrib d and sworn to before me this c3/
day of 47 A.
1987.
NOTARY UBLIC
~-"+'<lfz(a)~P)r~
Cj,gg
Attachment 1 to AEP:NRC:1056 NRC Bulletin 88-02 Rapidly Propagating Cracks in Steam Generator Tubes
Attachment 1 to AEP:NRC:1056 Page 1
BACKGROUND NRC Bulletin 88-02 addresses the steam generator tube rupture incident that occurred at Virginia Electric and Power Company's North Anna Unit 1.
North Anna's steam generators are Westinghouse (W) Series 51 with 0.875 inch O.D. by 0.050 inch nominal wall thickness Inconel 600 tubes.
While operating at 100 percent power on July 15,
- 1987, the tube at R9C51 in SG C ruptured, with a resultant primary-to-secondary leak rate of between 550 and 637 gpm.
The failure mechanism was subsequently classified as high cycle flexural fatigue superimposed on an elevated mean stress.
Tube denting at the top support plate intersection has been identified as the source of elevated mean stress levels as well as "the most significant contributor to the occurrence of excessive vibration."
Denting may also have contributed to fatigue stress concentration.
This report has been prepared in response to the "Action Requests" outlined in the bulletin.
The NRC staff concluded that all three of the following conditions must be present for a North Anna type fatigue failure to occur:
(1) denting at the uppermost support plate; (2) a fluid elastic stability ratio approaching that for North Anna's R9C51 tube; (3) absence of effective AVB support.
The responses outlining compliance with each action request have been prepared in light of this condition.
Action Re uest A
Recent tube inspection data for Cook Units 1 and 2 has been reviewed for. evidence of denting at the uppermost, or
- seventh, support plate.
Eddy current records for Unit 1 inspections of May 1985 and July 1987 and Unit 2 inspections of September
- 1985, May 1986, March 1987 and September 1987 were reviewed.
The action request states that records may be considered adequate for this review "if at least 3% of the total steam generator tube population was inspected at the uppermost
Attachment 1 to AEP:NRC:1056 Page 2
support plate during the last 40 calendar months."
All of the inspections cited above have, in fact, included 100% of the tubes, with the following extents a.
(1)
Unit 1, May 1985 (i) 100% inspected full length (2)
Unit 1, July 1987 (i)
Rows 1 and 2 inspected through and including the U-Bend (ii)
Rows 3 through 9 inspected through.and including the 7th hot leg support plate (iii)
Rows 10 through 46 inspected full length (3)
Unit 2, September 1985 (i) 100% full length inspected in SG 22 and 23 (ii)
Rows 6 through 46 inspected full length in SG 21 and 24 except for R9C45 and R9C46 (both in SG 24)
(iii)
Rows 2 through 5 inspected through and including the U-Bend in SG 21 and 24 (Note-all Row 1 tubes were plugged in 1984)
(iv)
SG 24 tubes R9C45 and R9C46 inspected through 7th hot leg support plate (4)
Unit 2, May 1986 (i) 100% inspected through and including the 7th hot leg support plate (5)
Unit 2, March 1987 (i) 100% inspected through and including the 7th hot leg support plate (6)
Unit 2, September 1987 (i) 100% inspected through and including the 7th hot leg support plate.
b See Table 1 for tabulated extents.
a U-Bend inspections include the 7th cold leg tube support plate intersection.
Furthermore, all the inspections cited have been reviewed by both a primary reviewer and an independent second party reviewer.
Maps indicating the location of uppermost support plate dents are attached.
No secondary side indications or imperfections have been reported at the uppermost tube
Attachment 1 to AEP:NRC:1056 Page 3
support plate.
There are a total of 45 dents for Unit 1 and 45 dents for Unit 2 that have been, reported in one outage or another:
~lna ecti.on Number of Upper Support Plate Dents Reported
~Cold Le H~ot Le U-1 5/85 U-1 7/87 13 13 16 21 U-2 9/85 U-2 5/86 U-2 3/87 U-2 9/87 1
0 0
0 16 19 22 27 The total number of dents at the uppermost support plates for the most recent outages do not add up to 45 on each of the units primarily because many of the previously reported dents were determined to be nonexistent.
Since Unit 1 and Unit 2 were subject to essentially a
100% inspection as noted in Table 1 within the last 40 months, the possibility of undetected denting is highly unlikely.
Action Re uest B
This action request applies to plants that have not experienced denting at the uppermost support plate.
Action Re uest C
Part 1
The following paragraphs describe the leak rate monitoring program currently in place at Donald C.
Cook Nuclear Plant.
~Back round Due to the occurrence of primary-to-secondary leakage in the Unit 2 steam generators resulting first from Row 1-U-bend cracking and later from secondary side corrosion in the tubesheet crevice region, Indiana Michigan Power has taken several measures to become attuned to primary-to-secondary leak detection and trending and has always acted conservatively with respect to Technical Specification leak rate limits.
An example of Indiana Michigan Power's commitment to leak rate monitoring is the installation and implementation of the Eberline SPING radiation monitoring system.
The Eberline SPING Monitor is a state-of-the-art, self-contained microprocessor-based radiation detection system.
The microcomputer performs the
Attachment 1 to AEP:NRC:1056 Page 4
tasks of data acquisition, history file creation, data management, operational status checking and alarm determination; operators communicate with this system through a central control terminal located in each control room.
Indiana and Michigan demonstrated conservatism with respect to leak rate limits can best be exemplified by the administrative policy which initiates shutdown actions at less than 60 percent of the allowable leak rate (0.2 gpm in lieu of 0.347 gpm which is the Technical Specification value of 500 gal. per day per steam generator).
Leaka e Measurement and Trendin Methods Primary-to-secondary leak rates are calculated from steam generator blowdown grab sample tritium at least once per day.
Additional sampling and calculations based on tritium are performed if the chemical supervisor notes any significant change in the leak rates or questions the accuracy of an analysis.
Grab sample xenon activity analyses are also performed on steam jet air ejector exhausts at least once per day and the leak rate is determined.
In addition to analyses performed on grab samples, the steam generator blowdown composite flow and steam jet air ejector (SJAE) and gland seal condenser exhauster (GSCE) discharges are continuously monitored and alarmed in the control room.
Although all three of these readouts can be used to estimate primary-to-secondary leak rate, the primary means of estimating leak rate on line is accomplished by monitoring SJAE activity.
The on-line blowdown composite flow is currently monitored by the Vestinghouse Radiation6Monitoring Sys)em which has a range sensitivity of 2.4 X 10 to 2.4 x 10
+Ci/cc.
SJAE and GSCE are both monitored by state-of-the-art Eberline SPING noble gas monigors which have a range sensitivity of 5.8 X 10 to 1.86 X 10$ 401/cc.
Operators are provided with updated correlations of primary-to-secondary leak rate as a function of SJAE activity levels so that leakage measurement is estimated continuously.
These correlations are updated based on primary and secondary side activity grab sample analyses and SJAE flow.
SJAE activity trending is extracted directly from the Eberline history management files.
An updated hardcopy of these files is printed every 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />.
In addition, blowdown sample analyses are recorded and trended daily.
Attachment 1 to AEP:NRC:1056 Page 5
Alarms The steam generator blowdown radiation monitor is set to alarm in accordance with the Offsite Dose Calculation Manual (ODCM) at 3 X 10 ~i/cc.
The Technical Specification limit 'on secondary side coolant activity is 0.10~i/cc.
Receipt of a "High" alarm on the steam generator blowdown monitor initiates steam generator blowdown and sampling line isolation.
Operators are required to verify this automatic function.
Grab samples are analyzed to determine the extent of primary-to-secondary leakage.
Alarms on the SJAE and GSCE are also set in accordance with the40DCM; the "High" alarm is currently set at 4.77 X 10 p Ci/cc while t$e "Alert" alarm is set at 60% of this value or 2.86 X 10 P.Ci/cc.
Upon receipt of an "Alert" alarm signal from either a SJAE or GSCE monitor, a grab sample of the respective effluent is taken and analyzed.
Upon receipt of a "High" alarm from either the SJAE and
- GSCE, additional steam generator blowdown analyses are performed to determine the extent of the primary-to-secondary leak.
The current SJAE "High" alarm setting corresponds to roughly 1/10 the expected activity level expected for a 0.2 gpm primary-to-secondary leak.
Administrative Limits Once primary-to-secondary leak rates approach 0.1 gpm, blowdown sampling frequency is increased to once per 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />.
The current administrative limit set on leak rate is 0.2 gpm.
When this limit is believed to be reached, the unit is brought down to 50% within approximately 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />.
Cold shutdown is achieved within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
Action with Ino erable Radiation Monitors Current procedures require the following grab sample surveillance frequency in the event of an inoperable monitor:
Ino erable Monitor Sam le Fre uenc Steam Generator Blowdown Liquid Monitor (i)
When blowdown specific activity
'< 0.01 P.Ci/gram dose equivalent I-131, sampling frequency is at least once per 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
(ii)
When blowdown specific activity
> 0.01~i/gram, dose equivalent I-131, sampling frequency is at least once per 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />.
Attachment 1 to AEP:NRC:1056 Page 6
Ino erable Monitor Sam le Fre uenc SJAE Noble Gas Monitor Grab sample frequency is at least once per 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> and gross analysis is performed within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
GSCE Noble Gas Monitor Grab sample frequency is at least once per 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> and gross activity analysis is performed within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
SJAE Flow Rate Monitor Flow rate read locally every 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />'SCE Flow Rate Monitor Flow rate read locally every 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />.
Effectiveness of Monitorin Pro ram The monitoring program in place at Cook compares favorably when evaluated against the assumed time dependent leakage curve presented in Figure 1 of the bulletin.
The curve assumes that a leak will progress from roughly 10 to 300 gallons per day over a period of 5300 minutes (88 hours0.00102 days <br />0.0244 hours <br />1.455026e-4 weeks <br />3.3484e-5 months <br />).
Even assuming that the Eberline monitor on the SJAE was unavailable, SJAE effluent would be sampled at least every eight hours or roughly 11 times during that period.
Steam generator blowdown samples would also be taken at least three times during this period.
Furthermore, if significant radioactivity increases are noted in steam jet air ejector
- samples, additional blowdown samples will be taken and analyzed.
Once the leak rate as determined by tritium level in blowdown samples approaches O.l gpm, the steam jet air ejector activity samples are taken and evaluated within thirty minutes.
If the activity level continues to rise, SJAE samples will be monitored with sufficient frequency to indicate to plant management that either the 0.2 gpm limit will likely be exceeded or the activity level (and hence the leak rate) has stabilized.
Blowdown samples will also be taken once a 0.1 gpm leak rate is exceeded,
- however, a
tritium analysis does require a 90 minute turn around time.
If the SJAE monitor is available and the leak rate exceeds 0.1
- gpm, SJAE activity is closely monitored and verified by sampling.
If it appears that the 0 '
gpm limit will be
- exceeded, the unit will be brought down.
Again, the unit is brought down to 50% power within approximately one hour and to cold shutdown within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
Attachment 1 to AEP:NRC:1056 Page 7
The plant has historically reacted to increasing leak rates in the above described manner.
The plant's excellent record of detecting, confirming and reacting to primary-to-secondary leak rates demonstrates that procedures and instrumentation currently in place are adequate.
When evaluating the monitoring program against the assumed tube fatigue failure leak rate vs.
time curve, we believe that even with a disabled monitoring system, plant personnel will be able to discern the trend leading to fatigue failure and reduce the affected unit's power level well within the prescribed limits.
Action Re uest C
Part 2
Lon Term Corrective Actions (1)
Due to the pervasiveness of the secondary side corrosion on Unit 2 at the tubesheet
- regions, the steam generators have been scheduled to be replaced beginning in the spring of 1988.
The new generators in Unit 2 will incorporate stainless steel tube support plates, thus alleviating the denting and fatigue concerns resulting from carbon steel support plate corrosion.
In addition, the new tube bundles will incorporate an enhanced AVB design which minimizes tube vibration in the U-bend region.
(2)
To mitigate the effects of secondary side corrosion at the tubesheet
- region, the secondary side of the steam generators in both units is being treated with boric acid.
In addition to retarding secondary side tube corrosion, boric acid treatments have been proven. to inhibit the formation of magnetite and hence minimize denting.
This boric acid treatment will continue on Unit 1.
(3)
The previously described leak rate monitoring program will remain in effect.
(4)
Due to hot leg secondary side corrosion concerns, the extent of future Unit 1 inspections will continue to be performed at levels well in excess of the Technical Specification requirements.
Inspection of any tubes in rows potentially susceptible to North Anna type failures (specifically rows 8, 9 and 10) will include both the hot and cold leg 7th support plate intersections.
Attachment 1 to AEP:NRC:1056 Page 8
(5) If and when denting is realized within the potentially susceptible
- rows, AVB insertion depth will be assessed.
Plugging and stabilization of potentially susceptible tubes or operational changes to reduce stability ratios will be implemented as required.
An alternative assessment of the potential for such a failure has been implemented in lieu of the actions described in subparagraph (a) and (b).
Sub ara ra h a I
Subparagraph (a) suggests that "the analysis should include an assessment of stability ratios (including flow peaking effects) for the most limiting tube locations to assess the potential for rapidly propagating fatigue cracks.
This assessment would be conducted such that the stability ratios are directly comparable to that for the tube which ruptured at North Anna."
Westinghouse determined in their preliminary assessment (and reiterated in their final report October 1987) that "the ruptured tube is considered to have a worst case combination of loading conditions (i.e., highest flow peaking factor) and fatigue properties (i.e,, denting)."
Therefore, stability ratios for Cook have been calculated assuming that the worst flow peaking factor for Cook is the same as that for the failed tube at North Anna.
Both North Anna and the Cook units have Series 51 steam generators with 3388 mill annealed Inconel 600 (0 '75 inch O.D. by 0.050 inch nominal wall thickness) tubes.
For a given tube, the relative stability ratio is a function of flow conditions only (recirculation ratio, pressure, steam flow and flow peaking factor).
For a R9C51 tube, the stability ratios relative to North Anna's failed tube are 0.91 and 0.92, respectively, for Cook Units 1 and 2 at 100%
power.
At the current administrative power limit of 90% and 80% on Unit 1 and Unit 2, the respective ratios are actually about 0.86 and 0.83.
Sub ara ra h b Subparagraph (b) suggests that "the analysis would include an assessment of the depth of penetration of each AVB.
The purpose of the assessment is two fold:
(1) to establish which tubes are not effectively supported by AVB's and (2) to permit an assessment of flow peaking factors."
Westinghouse's design of the series 51 steam generators at
Attachment 1 to AEP:NRC:1056 Page 9
Cook specified AVB insertion to and including row 11.
Since the AVB insertion depth for the Cook steam generators includes rows 11 through 46, the only tubes of concern in terms of a North Anna type fatigue failure are those tubes in rows 1 through 10.
Westinghouse's assessment further narrowed the rows of concern to rows 8 through 10.
Of all the eddy current inspections carried out on both units, only two tubes were identified within rows 8 through 10 as having experienced denting.
The two tubes detected were:
Unit 1
1 S.G.
11 12 Row 10 10 Column 19 58 Leg Outages H
5/85 H
5/85 Although these two potentially unsupported tubes were reportedly dented in May 1985, they were not found to be dented in the July 1987 inspection.
Even though the 1987 inspection revealed that the denting observed in 1985 did not in fact exist, AEP for conservatism requested Westinghouse to review the eddy current tapes to determine whether these tubes were supported by AVB's.
Westinghouse reported.the following:
Cook Plant Anti-Vibration Bar Location Anal sis S/G Row Column Number AVB's Location 1st Seen 2nd 7th Seen C-L 11 10 19 12 10 58
¹1 AVB
¹4 AVB 7-CL
.¹1 AVB
¹4 AVB 7-CL 16.0*
28.0 19.3 27.9 19.5 31.0 20.1 29.0 50.1 52.4
- Distances given in table represent axial distance (inches) from the 7th hot leg support plate.
This not only verifies that these tubes are supported by the lower set of AVB's, but, it also verifies that these tubes are supported on both sides of the tubes.
(See attached Figure 1).
Verification of bilateral AVB support constitutes our criteria for determining whether a tube is effectively supported.
This criteria shall be applied in the future analyses when a row 8, 9, or 10 tube is dented at the uppermost support plate.
Attachment 1 to AEP:NRC:1056 Page 10 Summa of Evaluation A complete review of eddy current inspection data for evidence of denting at the 7th support plate has been completed.
A total of two tubes were identified as dented in steam generators 11 and 12 in the May 1985 inspection that fall into one of the three rows sensitive to a North Anna type fatigue failure.
These dents did not show up in the July 1987 inspection.
The apparent explanation for the revised call is that recent signals-are "clearer", thus allowing more definitive interpretation.
The clearer data may be attributed to the removal qf deposits by continuing secondary side boric acid treatment.
Nevertheless, Westinghouse has verified'hat both these tubes are in fact effectively restrained by AVB's.
Bundle flows (both design and administrative operation) for steam generators in both the Cook units are below 90% of North Anna's.
The relative stability ratio (for the R9C51 failed tube configuration) is below 90% for both the Cook units at current administrative power levels, and is only marginally above for full load operation (0.91 and 0.92, respectively).
Additional confidence in safe operation is gained by the knowledge that a 100% inspection on Unit 1 and a virtually.
100% inspection on Unit 2 have been performed within the last 40 months, far in excess of Technical Specification requirements.
Long term corrective action will include:
Replacement of the Unit 2 steam generators (with stainless steel'support plates and improved AVB design);
Continued secondary side boric acid treatment on Unit 1; Commitment to perform eddy current inspections through the 7th support plate on the cold leg within the rows of concern and continued eddy current inspections in excess of Technical Specification requirements on Unit 1.
If denting is realized within the three critical rows, AVB insertion depth will be assessed.
Plugging and stabilization or operational changes to reduce stability ratios will be instituted, if required.
Attachment 1 to AEP:NRC:1056 Page 11 Table 1
Inspection Extents Unit 1
1 2
2 2
2 Outage 5/85 7/87 9/85 5/86 3/87 9/87 F/L 13493 10147 12576 3823 447 1
U-Benda 0
716 543 77 173 113 7H 0
2602 2c 9040 12167 12565 Totalb 13493 13465 13121 12940 12787 12679 a
U-Bend inspections include the 7th cold leg tube support plate intersection.
b In all cases, this also represents the total, number of tubes available for inspection.
c Tubes R9C45 and R9C46 were inspected through and including 7H.
They have not been full length inspected in subsequent outages.
D. C.
COOK NUCLEAR PLANT AEP:NRC:1056 AVB 04 AVB 51 AVB 54 1st seen 2nd seen AVB Nl 2nd seen 1st seen Cold Leg Hot Leg Typical Row 10 Steam Generator Tube/
AVB Insertion Schematic Axial Distance Ficiure 1
7th Support Plate 7th Support Plate
UPPERMOST TUBE SUPPORT PLATE DENTS (RESPONSE TO NRCB 88-02)
PLANT:
OC COOK UNIT i GENERATOR if TOTAL TUBER 33BB X-Oem' OOLO LEe ta ta le) 0 ~ OEN8 - Nt LES TOP TSP g TOTAL TIAIEB ASSIIRRIk
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II%ST Obt Led)
C INZZLC